An electric power system comprises a power transmission and/or distribution network interconnecting geographically separated regions, and a plurality of substations at the nodes of the power network. The substations include equipment for transforming voltages and for switching connections between individual lines of the power network. Power generation and load flow to consumers is managed by a central Energy Management System (EMS) and/or supervised by a Supervisory Control And Data Acquisition (SCADA) system.
In the past years, continued load growth without a corresponding increase in transmission resources has resulted in reduced operational margins for many power systems world wide, and has led to operation of power systems ever closer to their stability limits. Likewise, load transmission and wheeling of power from distant generators to local load consumers has become common practice, and led to substantially increased amounts of power being transmitted through the existing networks, occasionally even causing transmission bottlenecks and electromechanical oscillations of parts of the electric power systems. These issues together with the on-going worldwide trend towards deregulation of the electric power markets on the one hand and the increased need for accurate and better network monitoring on the other hand, have created a demand for dynamic wide area monitoring, protection and control that goes beyond the rather static view as provided by SCADA/EMS.
A state or condition of an electric power system at one specific point in time can be obtained from a plurality of synchronized phasor measurements or snapshots collected across the electric power system or power transmission network. Phasors are time-stamped, complex values such as amplitude and phase, of local electric quantities such as currents, voltages and load flows, and can be provided by means of stand-alone Phasor Measurement Units (PMU). These units involve a very accurate global time reference, obtained e.g. by using the Global Positioning Satellite (GPS) system or any other comparable means, and allowing synchronization of the time-stamped values from different locations. The phasors are typically calculated at a rate of 10 to 60 Hz from an internal sampling rate of 2.4 kHz, and thus can provide a view on transient or sub-transient states. Conventionally, PMUs are placed at selected substations of a power network, and forward their measured phasor values to a central System Protection Centre at control level. In the U.S. Pat. No. 6,845,333, a protective relay as part of a Substation Automation system is disclosed, which comprises means for producing synchronized voltage or current phasor values as well as means for receiving voltage or current values from another, remote relay via a communication channel.
The mechanism by which interconnected synchronous machines in large power systems maintain synchronism with one another is through restoring forces which act whenever there are forces tending to accelerate or decelerate one or more generators with respect to other generators in the system. In addition, Power System Stabilizers (PSS) are provided to add damping torque to the generator oscillations by modulation of the generator excitation signal. PSS devices enhance small-signal stability and improve the damping of both plant mode oscillations and inter-area modes of power oscillation. Conventional PSS devices operate locally, using exclusively local measurements for decisions on how to control generator excitation or damp power system oscillations. These estimations or detections are based primarily on variations of shaft speed, terminal frequency, electric power and accelerating power of the machine and are typically sampled every 25 μs, i.e. at a sampling frequency of 40 kHz.
Power oscillations in fact give rise to variations in these quantities, but as also other phenomena may affect them, the detection of relevant power system oscillations from these measurements is a very complex task. Hence the general problem is that the measured quantities often are insufficient to efficiently detect the power system oscillations or the mode of oscillation. The U.S. Pat. No. 6,476,521 discloses a system protection scheme based on measurements of time-stamped signals in at least two locations of the power system that are evaluated in view of poorly damped power oscillations. Direct measurement of a node angle difference between the at least two points in a power system provides an improved picture of the rotor angle oscillations compared to indirect local measurements as evaluated in the case of conventional Power System Stabilizers (PSS).